Stabilizer Overhead Compressor Fundamentals

1. Purpose of Stabilizer Overhead Compression

The condensate stabilizer removes light hydrocarbon components (C₁ through C₃) from raw field condensate to produce a stable liquid product that meets pipeline vapor pressure specifications, typically below 10–12 psia Reid Vapor Pressure (RVP). The overhead vapor stream from this process contains a mixture of methane, ethane, propane, and smaller amounts of butanes and heavier components that must be managed effectively—either recovered as valuable product or disposed of in an environmentally compliant manner.

Stabilizer overhead compression serves the essential function of boosting this low-pressure vapor to a pressure suitable for delivery into a sales gas pipeline, fuel gas system, or downstream processing facility. Without compression, the overhead vapor would need to be flared or vented, resulting in lost revenue and regulatory non-compliance under increasingly stringent emissions regulations.

Overhead Vapor Composition

The composition of stabilizer overhead vapor varies significantly depending on the inlet condensate composition, stabilizer operating pressure, and column configuration. Understanding this variability is critical for proper compressor design and material selection:

The gas molecular weight for stabilizer overhead vapor typically falls in the range of 22–32 lb/lb-mol, which is notably heavier than dry natural gas (approximately 17–19 lb/lb-mol). This higher molecular weight directly affects compressor power requirements, discharge temperature, and the tendency for liquid condensation throughout the compression system.

Flash Gas vs. Reflux Drum Vapor

The overhead vapor source depends on the stabilizer column configuration. Two common arrangements produce different vapor characteristics:

• Flash stabilizer (no reflux): The overhead vapor exits the top of the column directly and is routed to the compressor suction scrubber. This vapor is relatively rich in C₃+ components because there is no reflux to wash back heavier material. Flash stabilizer overhead gas is typically 25–32 lb/lb-mol MW and may carry entrained liquid droplets from the top tray
• Refluxed stabilizer: A portion of the condensed overhead liquid is returned to the top tray as reflux, producing a leaner overhead vapor (lower C₃+ content) and better product quality control. Reflux drum vapor is typically 20–26 lb/lb-mol MW and is less likely to carry liquid, though mist carryover from the reflux drum is still possible

Typical Stabilizer Operating Conditions

Condensate stabilizers operate across a range of pressures depending on the desired product RVP, inlet condensate composition, and downstream sales gas pressure requirements:

Why Compression Is Required

Three primary drivers make stabilizer overhead compression necessary in modern condensate processing facilities:

• Revenue recovery: Stabilizer overhead vapor contains significant heating value (typically 1,200–1,800 BTU/scf) and recoverable NGL content. Compressing this gas for sale or further processing recovers value that would otherwise be lost to flaring. At typical gas prices, the recovered value frequently exceeds $50,000–$200,000 per year for a single stabilizer unit
• Regulatory compliance: Federal and state regulations increasingly restrict routine flaring and venting of associated gas. EPA NSPS Subpart OOOO and OOOOa requirements mandate vapor recovery or combustion controls on storage vessels and process equipment, making compression an operational necessity rather than an optional enhancement
• Pipeline pressure matching: Sales gas pipelines typically operate at 400–1,000 psig, well above stabilizer overhead pressures. Compression bridges this pressure gap to enable gas delivery into the pipeline system

2. Compressor Selection and Sizing

Selecting the appropriate compressor type and properly sizing the unit for stabilizer overhead service requires careful consideration of the gas composition variability, flow rate range, suction conditions, and discharge pressure target. The relatively low suction pressure, moderate flow rates, and variable composition characteristic of stabilizer overhead service narrow the selection to two primary compressor types: reciprocating and rotary screw machines.

Reciprocating Compressors

Reciprocating compressors are the predominant choice for stabilizer overhead service, particularly for applications requiring compression ratios above 3:1 or discharge pressures exceeding 500 psig. Their advantages in this service include:

• High compression ratio per stage: Reciprocating machines can achieve 3:1 to 4:1 compression ratio per stage (limited by discharge temperature), which often allows single-stage or two-stage compression to reach sales gas pressure
• Efficient at variable flow: Capacity can be controlled through suction valve unloaders, clearance pockets, or variable-speed drives, providing efficient turndown to 25–50% of rated capacity without excessive power waste
• Proven reliability: Decades of field experience in similar gas gathering and vapor recovery applications. API 618 provides comprehensive design standards for process reciprocating compressors
• High discharge pressure capability: Can achieve discharge pressures of 1,000+ psig in multi-stage configurations, suitable for high-pressure sales gas systems

The primary disadvantage of reciprocating compressors is their sensitivity to liquid carryover. Stabilizer overhead vapor with entrained condensate can damage suction and discharge valves, wash lubricant from cylinder walls, and cause hydraulic lock. Robust suction scrubbing is mandatory for reciprocating compressor installations in this service.

Rotary Screw Compressors

Oil-flooded rotary screw compressors offer an alternative for lower-pressure, moderate-flow stabilizer overhead applications. Their key characteristics in this service include:

• Liquid tolerance: Screw compressors can handle moderate amounts of liquid carryover (up to 5–10% by volume) without damage, which is advantageous given the condensation-prone nature of stabilizer overhead gas
• Simple operation: Fewer moving parts and no suction/discharge valves reduce maintenance requirements and improve availability in remote, unmanned installations
• Smooth flow delivery: Continuous compression without the pulsation inherent in reciprocating machines eliminates the need for pulsation dampeners and reduces piping vibration
• Limited pressure ratio: Maximum compression ratio is typically 4:1 to 5:1 per stage, and discharge pressure is generally limited to 350–500 psig per stage depending on manufacturer and gas composition

Selection Criteria Summary

Compression Ratio and Staging

The overall compression ratio is determined by the stabilizer overhead pressure and the required discharge pressure (sales gas pipeline or fuel gas system). When the required ratio exceeds the capability of a single compression stage, multi-stage compression with interstage cooling is necessary:

For multi-stage reciprocating compression, the optimal ratio per stage is determined by equalizing the ratio across all stages: r_stage = (P_discharge / P_suction)^1/n, where n is the number of stages. This approach equalizes the work distribution and minimizes total power consumption.

Power Estimation

Preliminary compressor power estimation for stabilizer overhead service uses the isentropic or polytropic method. For reciprocating compressors, the adiabatic head and efficiency approach per API 618 yields:

Where Q is the actual volume flow (acfm) at suction conditions, P_s and P_d are suction and discharge pressures (psia), k is the specific heat ratio (C_p/C_v), and η_ad is the adiabatic efficiency (typically 0.80–0.88 for reciprocating compressors). The specific heat ratio for stabilizer overhead gas is typically 1.15–1.25, which is lower than dry natural gas (1.26–1.30) due to the heavier molecular weight.

Gas Molecular Weight and Specific Heat Ratio Effects

The relatively high and variable molecular weight of stabilizer overhead gas has several important effects on compressor sizing:

• Higher power per MMSCFD: Heavier gas requires more work per unit mass to achieve the same compression ratio. A 30 MW gas requires approximately 15–20% more power than a 20 MW gas at the same ratio and flow rate
• Higher discharge temperature: The discharge temperature rises with compression ratio and is influenced by the specific heat ratio. Lower k values (heavier gas) produce lower discharge temperatures for the same ratio, which is a partially offsetting benefit
• Greater condensation tendency: Heavier gas has a higher dew point, increasing the likelihood of liquid formation in interstage coolers and at the compressor discharge. This must be accounted for in scrubber and separator sizing
• Variable composition effects: As stabilizer feed composition changes (seasonal, well decline), the overhead gas MW shifts, affecting compressor performance. Design should accommodate the full expected MW range with appropriate capacity control

3. Suction Scrubber and Inlet Conditioning

The suction scrubber is arguably the most critical piece of auxiliary equipment in a stabilizer overhead compressor installation. Its function is to remove all entrained liquid and solid particulates from the gas before it enters the compressor cylinders (reciprocating) or rotors (screw). Failure to provide adequate liquid knockout is the single most common cause of compressor damage, valve failure, and unplanned shutdowns in stabilizer overhead service.

Importance of Liquid Knockout

Stabilizer overhead vapor is inherently prone to liquid carryover for several reasons:

• Proximity to dew point: The overhead vapor exits the stabilizer column or reflux drum at conditions close to its hydrocarbon dew point. Any pressure drop in the piping between the stabilizer and the compressor suction (through control valves, elbows, or elevation changes) can cause retrograde condensation
• Ambient cooling: Long suction piping runs exposed to ambient temperature loss can cool the gas below its dew point, generating liquid slugs that travel with the gas flow
• Operational upsets: Stabilizer column upsets (flooding, foaming, feed rate changes) can cause liquid carryover from the column overhead or reflux drum that overwhelms downstream equipment
• Water condensation: If the gas contains water vapor (common when processing wet field condensate), free water may condense at suction conditions and must be removed to prevent corrosion and hydrate formation

Scrubber Sizing: Souders-Brown Method

The suction scrubber is sized as a vertical vessel using the Souders-Brown correlation to establish the maximum allowable gas velocity through the vessel cross-section:

Where V_max is the maximum superficial vapor velocity (ft/s), K_SB is the Souders-Brown capacity factor, ρ_L is the liquid density (lb/ft³), and ρ_V is the vapor density (lb/ft³). For compressor suction scrubbers in stabilizer overhead service, K_SB values of 0.15–0.20 ft/s are recommended—lower than typical production separator values (0.25–0.35) to provide additional safety margin for the liquid-sensitive compressor downstream.

Design vapor velocity is typically set at 75% of V_max to account for flow surges and compositional variability. The resulting vessel diameter must accommodate the maximum expected flow rate at the lowest expected suction pressure (worst-case actual volume flow).

Liquid Retention Time

The liquid section of the suction scrubber must provide adequate retention time for level control response and drainage. Recommended minimum retention times for compressor suction scrubbers are:

Mist Eliminator Selection

A mist eliminator is installed in the upper section of the suction scrubber to capture fine liquid droplets (typically below 10 microns) that cannot be removed by gravity separation alone. The two most common types for compressor suction scrubbers are:

• Wire mesh pads: Knitted wire mesh (typically 4–6 inches thick, 9 lb/ft³ density, 316 stainless steel) provides effective droplet capture through impaction and coalescence. Suitable for most stabilizer overhead applications where solid fouling is not a concern. Pressure drop is 0.5–1.5 inches H₂O at design velocity. Removal efficiency is 99.5%+ for droplets above 10 microns
• Vane-type (chevron) demisters: Multiple corrugated metal vanes force the gas through direction changes, impacting liquid droplets on the vane surfaces. More resistant to fouling and re-entrainment than wire mesh, making them preferred for services with paraffin deposition or corrosion product carryover. Pressure drop is 1–3 inches H₂O. Removal efficiency is 99%+ for droplets above 15–20 microns

Liquid Carryover Consequences

Understanding the specific damage mechanisms caused by liquid ingestion motivates the attention given to suction scrubber design and maintenance:

• Valve damage (reciprocating): Liquid slugs striking suction and discharge valves cause impact loading far exceeding the valve plate design strength. Valve plate fracture, seat erosion, and spring failure result in valve leakage, reduced efficiency, and eventual compressor shutdown. Valve replacement costs $2,000–$10,000 per valve, with typical compressors having 4–8 valves per cylinder
• Cylinder washout: Liquid hydrocarbons dissolve the lubricant film on cylinder walls and piston rings, causing metal-to-metal contact, accelerated wear, and scoring of the cylinder liner. Once scored, the liner must be re-bored or replaced—a major overhaul requiring cylinder removal
• Lubricant dilution: Condensed hydrocarbons mixing with crankcase oil reduce lubricant viscosity and load-carrying capacity, leading to accelerated bearing and crosshead wear. Oil analysis programs should monitor viscosity and hydrocarbon content to detect this condition
• Hydraulic lock: A slug of incompressible liquid trapped in the cylinder during the compression stroke can generate pressures sufficient to bend connecting rods, crack cylinder heads, or break crankshafts. This is a catastrophic failure mode that can destroy the compressor

Temperature Control at Suction

Maintaining the suction gas temperature above the hydrocarbon dew point is essential to prevent condensation between the scrubber outlet and the compressor cylinder inlet. In cold-climate installations, suction gas heating (via hot oil or electric heat tracing on the suction piping) may be necessary during winter months. Conversely, excessively high suction temperatures reduce compressor volumetric efficiency and increase discharge temperature, so an upper limit of approximately 100–120°F is generally targeted.

Anti-Surge Protection

While surge is primarily a concern for centrifugal compressors, reciprocating and screw compressors in stabilizer overhead service require protection against rapid pressure fluctuations and reverse flow. A check valve on the discharge line prevents backflow into the compressor when the machine trips. Recycle (bypass) control with an automatic recycle valve maintains minimum flow through the compressor during low-load conditions, preventing the suction pressure from dropping below the minimum operating point and avoiding excessive compression ratio that could lead to high discharge temperatures.

4. Discharge System and Aftercooling

The compressor discharge system must safely handle high-temperature, high-pressure gas and condition it for delivery to the downstream sales gas pipeline or fuel gas system. Proper design of the discharge piping, aftercooler, condensate knockout, and pressure control elements is critical for reliable operation and product quality.

Discharge Temperature Calculation

The temperature of gas leaving the compressor cylinder is a primary design constraint. Excessive discharge temperature accelerates valve degradation, carbonizes lubricant, and can cause auto-ignition of oil-gas mixtures in extreme cases. The theoretical isentropic discharge temperature is calculated as:

Where T_d and T_s are the discharge and suction temperatures in absolute units (Rankine), P_d/P_s is the compression ratio, and k is the specific heat ratio. The actual discharge temperature is higher than the isentropic value due to real-gas effects and mechanical inefficiency:

Note: Values assume 100°F suction temperature and include a 10–15% inefficiency factor above theoretical isentropic temperature. API 618 recommends a maximum discharge temperature of 300–350°F for reciprocating compressors to protect valves and lubricants. When the predicted discharge temperature exceeds this limit, a lower compression ratio per stage (and therefore more stages) is required.

Aftercooler Sizing

Aftercoolers reduce the compressed gas temperature to a level suitable for pipeline transport, metering, and downstream processing. Two common types are used in stabilizer overhead compressor installations:

• Air-cooled exchangers (fin-fan): Most common in field installations where cooling water is unavailable. Design approach temperature is 15–25°F above ambient dry-bulb temperature. Outlet temperature typically 100–130°F depending on climate and season. Air-cooled aftercoolers require significant plot space and parasitic fan horsepower (typically 1–3% of compressor driver power)
• Water-cooled exchangers (shell-and-tube): Used where cooling water is available, providing closer approach temperatures (5–15°F above cooling water temperature) and lower outlet gas temperatures. More compact than air-cooled units but require cooling tower infrastructure. Preferred in large plant settings where multiple compressors share a common cooling water system

Condensate Knockout

Cooling the compressed gas in the aftercooler frequently drops the gas temperature below the hydrocarbon dew point, condensing heavier components (C₃+ and water). A condensate knockout drum (or scrubber) downstream of the aftercooler removes this liquid before the gas enters the pipeline or downstream equipment. The knockout drum is sized using the same Souders-Brown methodology as the suction scrubber, but at the higher discharge pressure and post-cooler temperature conditions.

The condensed liquid from the discharge knockout drum is typically a mixture of hydrocarbon condensate and water (if present). This liquid is routed to a low-pressure condensate collection system, a three-phase separator for water/hydrocarbon separation, or back to the stabilizer feed for re-processing.

Pulsation Dampening

Reciprocating compressors generate pressure pulsations in both the suction and discharge piping due to the intermittent nature of the compression cycle. These pulsations cause piping vibration, fatigue failure at welds and fittings, and inaccurate flow metering. API 618 requires a pulsation analysis for all reciprocating compressor installations and specifies maximum allowable pulsation levels at the line connections:

• Pulsation dampeners (bottles): Large-volume vessels installed immediately at the compressor suction and discharge nozzles. The volume attenuates pressure pulsations by providing acoustic capacitance. Bottle volume is typically 5–15 times the cylinder swept volume
• Orifice plates and choke tubes: Flow restrictions within the pulsation dampener that provide acoustic resistance to further attenuate pulsations. Sized per the API 618 analog or digital pulsation analysis
• Design approach levels: API 618, Design Approach 2 (analog simulation) or Design Approach 3 (digital simulation) are recommended for stabilizer overhead service. Approach 1 (simplified analysis) may not adequately address the complex pulsation interactions in multi-cylinder, multi-stage installations

Pressure Control Philosophy

The discharge pressure control system must maintain stable compressor operation while delivering gas at the required pipeline pressure. Common control strategies include:

• Suction pressure control: The compressor capacity is modulated (via unloaders or speed control) to maintain constant suction pressure at the stabilizer overhead. This prevents the stabilizer column pressure from rising due to back-pressure from the compressor, which would affect stabilizer product quality
• Discharge pressure control: A back-pressure control valve or automated bypass maintains the required discharge pressure. Excess gas above pipeline capacity is recycled to suction or diverted to fuel gas
• Recycle control: An automated recycle valve opens when compressor capacity exceeds available gas volume, recirculating discharge gas back to the suction scrubber through a recycle cooler. This prevents the compressor from operating in a deep vacuum or excessively low suction pressure condition

Integration with Sales Gas and Fuel Gas Systems

The compressed stabilizer overhead gas can be delivered to several downstream destinations depending on the facility configuration:

• Sales gas pipeline: The gas must meet pipeline tariff specifications for heating value, hydrocarbon dew point, water content, and contaminant levels (H₂S, CO₂, total sulfur). Additional treating or dehydration may be required before pipeline delivery
• Fuel gas system: A portion or all of the compressed gas may be used as fuel for compressor drivers (gas engines), process heaters, or reboilers. A fuel gas conditioning skid with pressure regulation, filtration, and moisture removal is typically required
• Gas processing plant: In some configurations, the compressed gas is delivered to a central gas processing facility for NGL extraction, treating, and sales gas conditioning

5. Economics and Operational Considerations

The economic justification for stabilizer overhead compression rests on the balance between the capital and operating costs of the compression system and the revenue from recovered gas plus the avoided costs of flaring or venting. In most modern installations, the economics strongly favor compression due to increasing gas prices, NGL values, and the regulatory costs of non-compliance with emissions standards.

Vapor Recovery Economics

The primary economic driver is the value of the recovered gas that would otherwise be lost. The revenue calculation requires an estimate of the recoverable gas volume and its market value:

In addition to the direct revenue from gas sales, compression avoids several costs associated with flaring:

• Flaring penalties: Many jurisdictions impose fees or taxes on flared gas volumes, ranging from $0.50 to $10.00 per MCF depending on the regulatory environment
• Carbon credit value: Avoiding CO₂ emissions from flaring may generate carbon credits or avoid carbon tax liabilities. At $25–50 per metric ton CO₂, the avoided emissions value can be $25,000–$250,000 per year for a typical installation
• Permitting costs: Routine flaring increasingly requires extensive permitting, monitoring, and reporting that adds administrative cost to operations

Emission Reduction and Environmental Compliance

Stabilizer overhead compression plays a central role in meeting federal and state air quality requirements for oil and gas production and processing facilities:

• EPA NSPS Subpart OOOO/OOOOa: These regulations require operators to reduce volatile organic compound (VOC) emissions from storage vessels and process equipment by 95%. Vapor recovery through compression is one of the accepted compliance methods
• State regulations: Many producing states (Texas, Colorado, North Dakota, New Mexico, Wyoming) have implemented gas capture requirements that mandate minimum percentages of produced gas to be captured rather than flared, typically 90–98% capture targets
• Methane reduction initiatives: Industry voluntary programs and potential federal methane regulations create additional incentives for comprehensive vapor recovery, including stabilizer overhead gas that might otherwise be vented through tank thief hatches or pressure relief devices

Operating Cost Estimation

The major operating cost categories for stabilizer overhead compression include:

Common Operational Problems

Stabilizer overhead compressor installations face several recurring operational challenges that affect reliability and availability:

• Liquid slugging: The most frequent cause of unplanned shutdowns. Liquid slugs from stabilizer upsets, piping condensation, or scrubber malfunction damage valves and rings. Prevention requires properly sized and maintained suction scrubbers, high-level shutdowns with fast response, and adequate piping slope to drain low points back to the scrubber
• Corrosion from acid gas components: CO₂ and H₂S in the overhead gas can cause severe corrosion when free water is present, particularly in the suction scrubber, interstage piping, and aftercooler. Material selection per NACE MR0175/ISO 15156 is essential for sour gas service. Carbon steel components require continuous chemical inhibition or replacement with corrosion-resistant alloys
• Packing and ring wear: The heavier-than-typical gas composition, combined with potential liquid carryover and solid particulates (sand, scale, corrosion products), accelerates wear on piston rings and packing. Monitoring rod drop (piston ring wear indicator) and packing leakage rates provides early warning of required maintenance
• Valve fouling: Carbon deposits from lubricant breakdown, polymer formation from reactive gas components, and scale from corrosion products can foul compressor valves, reducing their sealing capability and increasing valve temperature. Regular valve inspections and prompt replacement of fouled valves maintain compression efficiency
• Variable flow and composition: Changes in stabilizer feed rate, composition, and operating pressure cause corresponding changes in overhead gas flow rate and composition. The compressor must accommodate these variations through capacity control systems (unloaders, speed control) without excessive recycling or operation at sub-optimal efficiency

Turndown Capability

Stabilizer overhead gas rates vary significantly with condensate production rates, which may decline over the life of a well or field. The compressor must provide effective capacity control across a wide range:

• Reciprocating compressor turndown: Suction valve unloaders (fixed or variable volume clearance pockets) provide step or continuous capacity reduction to approximately 25–50% of rated capacity. Below this range, a recycle (bypass) system returns discharge gas to suction through a cooler. Variable-speed drives offer the most efficient turndown but add capital cost
• Rotary screw compressor turndown: Slide valve or variable Vi (internal volume ratio) control provides continuous capacity modulation to approximately 50% of rated flow. Below 50%, efficiency drops significantly and recycle control is needed

Vapor Recovery Unit (VRU) Alternatives

For smaller stabilizer installations or remote locations where a full compressor package is not economically justified, alternative vapor recovery approaches may be considered:

• Ejector systems: A high-pressure motive gas (sales gas or instrument gas) entrains the low-pressure stabilizer overhead vapor through a venturi, boosting it to pipeline pressure without rotating equipment. Ejectors have no moving parts and require minimal maintenance, but they consume motive gas and are limited in compression ratio (typically 2:1 to 3:1)
• Small rotary vane VRUs: Compact vapor recovery packages using rotary vane compressors can handle 50–500 MSCFD at compression ratios up to 4:1. These are commonly used for tank vapor recovery and can also serve small stabilizer overhead applications per API 11P
• Enclosed combustion devices (ECDs): When vapor recovery is not economic, the overhead gas must be destroyed in an enclosed combustor or vapor combustion unit that achieves 95%+ destruction efficiency to meet NSPS requirements. This is the compliance alternative to compression, but it recovers no revenue from the gas

Environmental Compliance Summary

References

1. GPSA, Chapter 16 — Hydrocarbon Recovery
2. API Standard 618 — Reciprocating Compressors for Petroleum, Chemical, and Gas Industry Services
3. API Standard 11P — Specification for Packaged Reciprocating Compressors for Oil and Gas Production Services
4. EPA 40 CFR Part 60, Subpart OOOO — Standards of Performance for Crude Oil and Natural Gas Facilities
5. EPA 40 CFR Part 60, Subpart OOOOa — Standards of Performance for Crude Oil and Natural Gas Facilities for Which Construction, Modification, or Reconstruction Commenced After September 18, 2015
6. NACE MR0175/ISO 15156 — Petroleum and Natural Gas Industries: Materials for Use in H₂S-Containing Environments